Tag Archives: Encana

The San Juan Basin: What You Need to Know

General Information
Why I should care: It’s a new horizontal play with some interesting production results.
Geographical location:  Northwest New Mexico.
Producing formations: Gallup, Mancos.
Main operators: Encana (ECA), WPX Energy (WPX).
Leasehold: ECA (176k net), WPX (31k net).
Average well cost: $4.5MM.
Average Royalty: 18%.

Average Peak Month Production by Formation
Gallup (27 wells): 275 BOPD and 406 Mcfpd (81% Oil).
Mancos (9 wells): 194 BOPD and 265 Mcfpd (71% Oil).

Source: www.thewellmap.com / New Mexico Oil Conservation Division.

Average Peak Month Production by Operator
ECA (27 wells): 215 BOPD and 409 Mcfpd (74% Oil).
WPX (6 wells): 391 BOPD and 318 Mcfpd (87% Oil).

Source: www.thewellmap.com / New Mexico Oil Conservation Division.

Average Peak Month Production by County
Rio Arriba (3 wells): 173 BOPD and 332 Mcfpd (56% Oil).
Sandoval (14 wells): 354 BOPD and 545 Mcfpd (79% Oil).
San Juan (16 wells): 175 BOPD and 271 Mcfpd (79% Oil).

Source: www.thewellmap.com / New Mexico Oil Conservation Division.

Largest Well by Cumulative Production

Source: www.thewellmap.com.

Smallest Well by Cumulative Production

Source: www.thewellmap.com.

Assuming $90 oil, $3.50 gas, 80% NRI and $4.5 well cost, a company needs to recover approximately 60 MBO (thousand barrels of oil) and 65 MMcf (million cubic feet of natural gas) to break even. Of the 10 wells that have been producing in the play for two years or longer, 3 have broken even. These three wells had peak production rates ranging from 275 BOPD and 718 Mcfpd to 535 BOPD and 854 Mcfpd. These ranges give us some parameters which will alow us to judge the ecoomics of new wells coming on.

The average peak month rates for wells spudded in 2013 are 329 BOPD and 400 Mcfpd, numbers that are similar to our early wells that have broken even. While it’s very early in this play, I think there’s reason to believe the average San Juan Basin well will pay back in two to three years which makes it competitive with current major plays from an economics standpoint. Will it be as big? Highly doubtful, but it could provide a nice production/earnings bump for the play’s early entrants.


Largest Oil and Gas Wells by Formation

Note: Added Powder River Basin well on June 10, 2013

I don’t usually talk about “largest wells” in formations or plays because they aren’t representative of the productivity or economics of a play as a whole. With that said, it’s still good to know where the biggest wells are being drilled because that usually indicates there’s a lot of oil in the area (whether it can be extracted consistently and economically is another matter).

Note: Peak month rate oil/gas is the amount produced in a given month divided by 30 days.

Well Name: Behr 11-34
Operator: Whiting (WLL)
County, State: Mountrail, ND
Formation: Bakken
Spud Date: April 15, 2008
Peak Month Rate Oil: 1,492 BOPD
Peak Month Rate Gas: 1,008 Mcfpd
Cumulative Oil: 911,627 BO
Cumulative Gas: 558,996 Mcf
Latest Monthly Rate Oil: 273 BOPD
Latest Monthly Rate Gas: 242 Mcfpd
Source: North Dakota Oil & Gas Commission/The Energy Harbinger.

Well Name: Jendrusch Unit 1H
Operator: Plains Exploration and Production (PXP)
County, State: Karnes, TX
Formation: Eagle Ford
Spud Date: April 21, 2012
Peak Month Rate Oil: 2,551 BOPD
Peak Month Rate Gas: 3,917 Mcfpd
Cumulative Oil: 341,352 BO
Cumulative Gas: 629,981 Mcf
Latest Monthly Rate Oil: 681 BOPD
Latest Monthly Rate Gas: 1,825 Mcfpd
Source: Texas Railroad Commission/The Energy Harbinger.

Well Name: Frye Ranch 2012H
Operator: Forest Oil (FST)
County, State: Wheeler, TX
Formation: Granite Wash/Hogshooter
Spud Date: March 23, 2010
Peak Month Rate Oil: 2,149 BOPD
Peak Month Rate Gas: 20,630 Mcfpd
Cumulative Oil: 327,782 BO
Cumulative Gas: 6,081,260 Mcf
Latest Monthly Rate Oil: 70 BOPD
Latest Monthly Rate Gas: 1,444 Mcfpd
Source: Texas Railroad Commission/The Energy Harbinger.

Well Name: Livestock 1-25H
Operator: SandRidge Energy (SD)
County, State: Grant, OK
Formation: Mississippian Lime
Spud Date: March 18, 2012
Peak Month Rate Oil: 1,595 BOPD
Peak Month Rate Gas: 3,909 Mcfpd*
Cumulative Oil: 170,398 BO
Cumulative Gas: NA
Latest Monthly Rate Oil: 214 BOPD
Latest Monthly Rate Gas: NA
Source: Oklahoma County Commission/The Energy Harbinger.
*Natural gas data is not publicly available for this well. Rate was computed using IP rates in the completion report.

Well Name: Dolph 27-1HZX
Operator: Anadarko Petroleum (APC)
County, State: Weld, CO
Formation: Niobrara
Spud Date: January 9, 2011
Peak Month Rate Oil: 730 BOPD
Peak Month Rate Gas: 1,595 Mcfpd
Cumulative Oil: 154,287 BO
Cumulative Gas: 568,554 Mcf
Latest Monthly Rate Oil: 71 BOPD
Latest Monthly Rate Gas: 331 Mcfpd
Source: Colorado Oil and Gas Commission/The Energy Harbinger.

Well Name: Anderson 18H-1
Operator: Encana (ECA)
County, State: Amite, MS
Formation: Tuscaloosa Marine Shale
Spud Date: January 15, 2012
Peak Month Rate Oil: 840 BOPD
Peak Month Rate Gas: 267 Mcfpd
Cumulative Oil: 115,991 BO
Cumulative Gas: 35,075 Mcf
Latest Monthly Rate Oil: 169 BOPD
Latest Monthly Rate Gas: 54 Mcfpd
Source: Mississippi Oil & Gas Board/The Energy Harbinger.

Well Name: Federal 16-10/3FH
Operator: Helis (Private)
County, State: Converse, WY
Formation: Frontier
Spud Date: July 16, 2011
Peak Month Rate Oil: 1,198 BOPD
Peak Month Rate Gas: 1,461 Mcfpd
Cumulative Oil: 270,530 BO
Cumulative Gas: 272,705 Mcf
Latest Monthly Rate Oil: 281 BOPD
Latest Monthly Rate Gas: 258 Mcfpd
Source: Wyoming Oil and Gas Conservation Commission/The Energy Harbinger.

For those of you who use the prototype version of the The Well Map, this is the type of data you’ll be able to access using the full version which will launch this summer.

Disclaimer: These are the largest wells in the above formation that I’m aware of. If you know of larger ones, feel free to disclose.

The Emerging TMS: Vast Oil Potential for Several Natural Gas Weighted Companies

Horizontal drilling and fracturing have been the keys which have unlocked vast oil reserves in North Dakota’s Bakken Shale and Texas’s Eagle Ford Shale.  The success companies have achieved while developing those two formations has led to the search for other shale formations with similar geological characteristics.  Enter stage left: the Tuscaloosa Marine Shale (TMS) which is a similar geological age to the Eagle Ford Shale.  The formation is deep, with depths ranging from 11,000’ to 15,000’, but contains plus 90% oil cuts and is prospective for economic quantities of oil in Louisiana and Mississippi (see map below).  Depths combined with low permeability in the TMS had previously dissuaded companies from developing the formation, but new technologies have led companies like Encana (ECA), Devon (DVN) and Goodrich (GDP) to explore the area with 21st century drilling techniques in their toolboxes.

Tuscaloosa Marine Shale Map
Source: LSU-Basin Research Institute.

The LSU-Basin Research Institute estimates the TMS contains seven billion barrels of oil reserves (unclear whether this is recoverable or oil-in-place) and spans eight million acres as shown by the highlighted band above.  Oil generation over-pressurized the formation in this band which has led to natural fracturing and increased permeability in certain zones.  The TMS refers to three different zones, the Upper Tuscaloosa (sand and shale), the Marine Shale and the Lower Tuscaloosa (sand and shale).  Until recently, the only well in the TMS was the Winfred Blades #1 well completed by Texas Pacific Oil Company in 1978.  This well was drilled in Tangipahoa Parish in Louisiana (Parish=County in Louisiana) and has recovered 20 thousand barrels of oil to date.

TMS Stratigraphic Map
Tuscaloosa Marine Shale_Stratigraphic-Map
Source: Louisiana DNR.

The Tuscaloosa Marine Shale has several advantages over other shale plays, including no severance tax on hydrocarbons recovered using horizontal wells in Louisiana for two years or until cost of well has been recovered and close proximity to the St. James terminal located on the Gulf Coast of Louisiana.  Crude oil sold to the St. James terminal has received a premium to WTI ranging from $10 to $20 during 2012 because the U.S. crude that reaches this terminal (most is currently sold at other terminals due to transportation costs) competes with higher priced Brent crude which is imported at St. James.  While this premium is currently an advantage for the play, expect it to decline as more U.S. oil from the Eagle Ford and the TMS is sold at St. James.

Disadvantages for the TMS are that it’s a high-cost, unproven play.  The high costs stem not only from its depth (deeper than both the Bakken and the Eagle Ford) and low permeability, but from complexities due to the thin layer from which natural fracturing (thus increased permeability) exists.  GDP is a micro-cap that is currently delineating its acreage in the TMS with four to five wells scheduled to be completed during the remainder of 2013.  In its third quarter earnings transcript, Goodrich revealed that the TMS zone which has natural fracturing is only ten feet thick.  This thin layer has led to issues with wellbore stability and resulted in well costs ranging from $14 to $16 million.  The company believes it’s making progress with this issue and expects well costs to decrease to around $12 million per well for wells completed with a 7,500’ lateral and 25 stage frac.

High resistivity in the TMS encouraged ECA and DVN to explore the play, with ECA drilling the first modern well in Amite County, Mississippi in 2007.  While this well has only recovered 35 thousand barrels of oil (MBbls) to date, the company has been more successful with its recent wells by tweaking its completion techniques to add more frac stages.

Its Weyerhaeuser 73H-1, spudded in August, 2011 in Saint Helena Parish, was completed with 17-frac stages and produced at a 30-day IP rate of 770 BOEPD (94% oil).  The company has achieved similar success with three wells in Southern Mississippi (North of the shoelaces on Louisiana’s boot), Horseshoe Hill 10H-1, Anderson 17H-1 and Anderson 18H-1 which achieved average 30-day IP rates of 695, 933 and 1,072 BOEPD, respectively.  The company will maintain its focus in Southern Mississippi, where it has 11 wells either drilling or permitted according to the Mississippi State Oil & Gas Board.

Encana’s TMS Results
Note: The above results were calculated by The Energy Harbinger using data provided by the States of Louisiana and Mississippi.  Data may differ from company reported figures, specifically in Louisiana where monthly production was assumed to be 30 days as the state doesn’t report the amount of days a well produced in a month.  For this reason, production may be understated.

Devon’s activity is focused across the boarder in Louisiana where its Weyerhaeuser 14H-1 in Saint Helena Parish produced at an average 30-day rate of 695 BOEPD (93% oil).  DVA’s other TMS wells include two drilled in the Tangipahoa Parish, the Soterra 6H-1 (completed in October, 2011) and the Thomas 38H-1 (completed during Q3’12), which produced at average 30-day IP rates of 176 BOEPD and 470 BOEPD, respectively.  The company completed four wells in the East Feliciana Parish during 2011 and 2012 with average 30-day IP rates ranging from 1 BOEPD to 285 BOEPD.

Devon’s TMS Results
Note: The above results were calculated by The Energy Harbinger using data provided by the States of Louisiana and Mississippi.  Data may differ from company reported figures, specifically in Louisiana where monthly production was assumed to be 30 days as the state doesn’t report the amount of days a well produced in a month.  For this reason, production may be understated.

While I would hesitate to put too much stock into these early results, ECA’s results in Amite County Mississippi are the largest and most consistent of the early wells drilled in the TMS.  Its Anderson 18H-1 well, mentioned above, has produced a Bakken like 85,454 barrels of oil durings its first 141 days of production.  At $95 oil (LLS currently in $105 range), this well would have grossed $5.8 million during this time period.  Now these wells are running expensive (ECA’s target wells cost is ~$14 million), but the early production results look robust.  If ECA can get its costs down, it may have a lot of oil on its hands.  Production from Louisiana’s Saint Helena Parish also looks strong, with both companies completing wells averaging more than 600 Bbls per day during their peak 30 days.

At a $12 million well cost, GDP believes EURs will need to be in the 350 MBOE range for the play to be economic.  It’s worth noting that DVN is targeting EURs at 400-600 MBOE (90% oil) which corresponds to an average 30-day IP rate of 700 to 900 BOEPD, whereas ECA revealed on its investor day that it has drilled several wells which it expects to recover hydrocarbons near  its target EUR of 730 MBOE (see table below).  While these target EURs are more than what GDP believes it will take to make the TMS economic, I caution that neither company has drilled many wells in the formation which makes it difficult to determine how large the play could be.  To that end, Halcon Resources (HK) is currently drilling a well in the Western part of the play in Rapides Parish, LA which should provide some intuition on play size.

Results over the near-term of this play will be important to pay attention to as they will be a catalyst for the companies involved.  The company-wide production cuts for its first movers, Encana, Devon and Goodrich, contained 6%, 37% and 23% oil, respectively, during the three months ended September 30, 2012.  One thing we do know about the TMS is that it’s oily meaning that it could provide all three of these companies a significant amount of oil reserves which will improve cash flows, reserve quality and valuations for each.  Below is a table describing each company’s position in the play.

TMS Position by Operator
Tuscaloosa-Marine-Shale_Operator Data

The Mississippian Lime: America’s Next Big Resource Play?

There’s no doubt that shale plays are sexy in the oil and gas realm these days, but prudent investors know all that really matters is return on investment.  Valuations are high in South Texas’ Eagle Ford Shale, where private equity firm Kohlberg, Kravis, Roberts & Co (KKR) recently agreed to pay $25k per acre in a participation agreement for up to 1/3 of Comstock Resources’ (CRK) undeveloped Eagle Ford acreage.  In North Dakota’s Bakken Shale, Bakken pure-play Kodiak Oil & Gas (KOG) paid $11,800 per acre in a deal late last year with two private companies.  If investors are looking for a value play, they should turn their heads to the Mississippian Lime, where acquisition prices averaged $3,284 per acre1 during the past year.

Source: Orion Exploration Partners August, 2011 Mississippi Lime Presentation

The Mississippian Lime, located in South-central Kansas and North-central Oklahoma (see map above), is a shallow carbonate play (mostly Limestone) with depths ranging from 3,000’ to 6,000’.  The Lime is not a new play, but an old producing field with more than 30 years of production and 14k vertical wells drilled.  It’s now being redeveloped using horizontal drilling and fracking techniques, and in that respect could be compared to the Permian Basin of West Texas.  While conventional production in the play stemmed from the “Mississippian Chat,” a reservoir with high porosity and permeability above the Lime, new development is targeting the tighter Mississippian Lime that underlies the Chat (see cross-section below).

Mississippian Lime Cross-Section

Source: Range Resources Corporate Presentation

Because the Lime is shallower than the Bakken and Eagle Ford, companies use smaller drilling rigs and cheaper proppants which has led to drilling and completion costs between $3 and $3.5 million, less than half of what an operator would pay in the Bakken or Eagle Ford.  The play is estimated to span 17 million acres with oil in place estimates ranging from 5.4 to 5.9 billion barrels of oil equivalent (BBOE).  This impressive amount of oil in place has companies like Sandridge Energy (SD) drilling three wells per section, which increases the recoverable reserves in the play.  For a more complete view on the Lime’s economics, let’s take a look at its most experienced operator, the aforementioned Sandridge Energy.

An intelligent discussion on the Mississippian Lime can’t be had without talking about Sandridge, who has drilled 382 horizontal wells or 44% of the total horizontal wells drilled in the play.  The company has amassed 1.7 million net acres in the Lime, from which it expects to generate estimated ultimate recoveries (EURs) of 456 thousand barrels of oil equivalent (MBOE) per well.  These EURs are based on 30-day average IPs of 275 barrels of oil equivalent per day (BOEPD), or put another way, a well that produced at an average rate of 275 BOEPD for 30-days is expected to produce an EUR of 456 MBOE.  How does this model out on a return basis?  SD estimates that a well which produces at a 30-day average rate of 244 BOEPD will have an 80% rate of return (ROR), a solid rate for a company whose average 30-day production rate is 325 BOEPD per well (119% ROR).  The table below shows how SD’s EUR estimate in the Lime compares to those of operators in other prolific plays in the U.S.

Play Economics

1Includes liquids content which prices at a discount to oil

As you can see from the table above, the Mississippian is by far the cheapest formation to produce from with respect to the peer group.  It’s worth noting that EOG Resources (EOG) and Continental Resources (CLR) are two of the premier operators in their respective plays and  if you were to take a survey of average well costs across those plays, I would expect current costs to average between $7 and $10 million per well.  The Mississippian is a play that produces more hydrocarbons per dollar than any of the above mentioned plays, with the main negative being a lower oil cut.  Despite its lower oil cut, SD is still reporting an average rate of return of 119%, a rate that has plenty of natural gas pricing upside.  The Lime also gets oilier as you move from East-to-West, and SD has reported several wells in Alfalfa County, Oklahoma with 30-day production rates in excess of 2,000 BOEPD (90%+ oil cut).  So while it’s a gassier oil play than some would like, oil cuts vary and returns are high.

These numbers aren’t going unnoticed by the oil and gas industry, but have prompted industry titans such as Chesapeake Energy (CHK), Apache (APA), Devon Energy (DVN), Encana (ECA) and Repsol (REP) to accumulate large acreage positions in the play.  CHK has approximately two million net acres in the Lime, making the play its top liquids play by acre and a key component of its shift towards liquids production.  The company plans to run 22 rigs in the Lime versus 30 in the Eagle Ford and 10 in the Utica during 2012, meaning this struggling company has levered itself to these three plays to resurrect its share price (down 73% from its high of $69.40 in July, 2008) and pay down its high debt levels.  Acreage positions of other large caps in the Lime: APA: 580k, DVN: 545k, ECA: 360k, and REP: 363k (see map below).

Range Resources (RRC) made its excitement for the Lime obvious during its second quarter earnings call, affirming its decision to market its Ardmore Woodford acreage to help finance the acceleration of its Mississippian development.  On the call, Jeffrey Ventura, President and CEO of RRC said regarding the planned divestiture, “Although the rate of return in the Ardmore Woodford is very good, the rate of return in our horizontal Mississippian play is even better.”  RRC’s excitement stems from two gushers it recently hit in the play, one which peaked at 1,363 BOEPD and a second which peaked at 1,950 BOEPD.  The company hit these wells after modifying its drilling and completion techniques by lengthening its laterals and fracs to 3,468’ and 17 stages versus 2,197’ and 12 stages previously.  For that reason, keep in mind that this is still an emerging play in its beginning stages with upside potential as companies tweak their completions.

Who’s where in the Lime?

Source: Map data was prepared based on public data provided by companies.  Please note that this map is only meant to show the acreage location of certain operators and no precedence is given to companies based on format or color.

The above map (prepared by The Energy Harbinger) shows where certain operators own acreage by county.  Because not all operators have disclosed where they’re operating and some companies have only partially disclosed the counties they operate in, this map is incomplete.  However, it does show the extent of the play and some of the more popular counties.  Net acreage by operator: APA: 580k; Atlas: 7.25k; Chesapeake: 2,000k; Devon: 545k; Equal: 7.25k; HK: 45.28k; Range: 152k; Sandridge: 1,700k.

Now we know the big operators that are in the Mississippian; however, there’s plenty of smaller companies with large acreage positions there too, including Petro River Oil.  This private company is interesting not only because it has amassed 100k net acres in the Lime, but because of its strong leadership team.  The company boasts two CEOs, Daniel Smith and Ruben Alba, who combined have several decades of experience in the oil and gas industry.  Mr. Smith has experience growing companies to maturity, serving as the Operations Engineer at XTO Energy before it was bought by Exxon Mobil (XOM) in December, 2009.  Mr. Alba brings an extensive oil service resume to the company.  Not only has he spent the majority of his career working for Halliburton Energy Services and Superior Well Services, but he also holds several patents in completion technology.  These Co-CEOs are supported by Luis Vierma, who spent several decades at Venezuelan state-owned oil and gas company PDVSA, where he served as the VP of Exploration and Production.  Bottom line, if there’s a private company to keep an eye on in the Lime, its Petro River.

If one of the negatives on the Lime is its lower oil cut, a second would be its high water content.  Sandridge is reporting an average of 2k to 3k barrels of water per day during the first 30-days of production per well.  To efficiently dispose of this water, companies must develop a network of salt water disposal wells (SWD) which they will inject produced water into for disposal in the Arbuckle Group formation (see Mississippian cross-section above).  While SWD wells add complexity to the Lime, they are relatively cheap to drill (~$265k per well) and will service water for between six and eight producing wells.  If we divide $265k by six (low end of estimate), we find that SWD wells add roughly $44k in expenses per well.

What can we expect from the Lime moving forward?  Companies like Devon and Encana, who’ve recently added 400k and 220k net acres, respectively, will be ramping-up production to delineate and hold their acreage positions.  The core of the play, lying in South-central Kansas and North-central Oklahoma (see map above), has been delineated for the most part and has proven to be consistent.  While the extension area hasn’t been delineated with horizontal production, the area holds more than 7k producing vertical wells and is an oilier field than the core.  SD is beginning to drill wells in the extension area of West-central Kansas (see above maps), where it holds 900k net acres.  The company’s initial extension wells are located in Hodgeman, Finney, Ford, Gray and Ness Counties and the company expects to announce results from these wells later this year.  Apache’s entire acreage position (580k net) lies in the extension portion of the play (see map above), and its delineation will be important to pay attention to.  If SD’s and APA’s wells prove to be as economic as the core, the land grab currently happening in the core will quickly spread North, creating one of the biggest plays in the United States.

1 Based on the following four deals: